Pipeline operators are often faced with a bewildering array of information about how reliable and safe their pipelines are, while in operation and during process upsets. This is especially prevalent when the fluid being transported is corrosive, although the risk can be reduced by selecting the most resilient material for transporting the fluid. However, with this approach for corrosion control, there always comes a sacrifice on the overall cost. In most cases, an ideology increasingly agreed by operators, contractors, and owners is to use carbon steel (CS) as an economical material for construction of pipelines. For highly corrosive environments, however, corrosion-resistant alloys (CRAs), in particular duplex stainless steel (DSS), remain the most cost-effective option since the risk of corrosion failure on CS lines is high and use of corrosion inhibition with CS is often either impractical, costly, or poses too high of a risk.
DSS was first introduced to the oil and gas industry in the late 1970s when it was selected for natural gas pipelines. At that time, this selection choice provided a critical commercial breakthrough for Duplex 2205 (UNS S32205). It helped pave the way for Duplex 2205 acceptance into not only the oil and gas industry, but into many other industries as well.
As such, DSS material also finds application in seawater cooling and fire protection systems, topside, and subsea production pipe work apart from flow lines and pipelines. However, this presupposes that all items in the bill of materials are consistently and repeatedly processed, heat treated, pickled and passivated, welded, installed, commissioned, operated, maintained, and deployed in environments within the limits of their application range. With over 40 years of wide-scale use of this alloy by the oil and gas industry, the overall experience has been good. However, intermittently problems can occur and drastically affect the “fit and forget” philosophy and adversely affect the operational excellence. One such high-profile recurring problem is discussed in this article.1
DSS pipes are joined by welding, which needs special controls to achieve the required quality. Failing to control welding correctly can, in the worst case, result in catastrophic failure and loss of life. The DSS pipe material under consideration was used by the operator in flowlines for various wet gas production and reservoir wells since 1984 in the Middle East. The operator operates the gas field where the produced and imported gas is fed and processed in the plant to remove heavier hydrocarbons and water. The heavier hydrocarbons are separated in the form of condensate. The condensate is stabilized and transported through pipelines. Gas produced from the field is exported through pipelines to a compressor station. Excess available gas (imported) from the gas network is injected in the reservoir and retrieved/produced, when required. In general, gas is compressed and injected into the reservoir for storage in the import mode and retrieved, processed, and transported to a compressor station for distribution in the export mode.
DSS pipe material was first installed at the well in 1984 and was in service for two years before becoming redundant. In 2004, the material was reused as another production flowline and was in service for six months. Later it was again made redundant. In 2016, the pipe material was recovered to construct another flowline for connection with a well. As part of this task, radiography tests were performed on 26 girth welds (Figure 1). Seven of these girth welds were identified with internal corrosion and pitting corrosion near the heat-affected zone (HAZ). However, no defects or flaws were identified on the parent material.
The fluid being transported was sour wet gas with high chloride content (2,000 ppm). The flowline operating temperature was 66 °C with 10.3 MPa operating pressure. The possible internal damage mechanisms investigated for DSS flowline welds were intermetallic phase precipitation, stress corrosion cracking, and chloride-induced pitting corrosion. The tests performed during the investigation included chemical analysis, pitting resistance equivalent number (PREN) calculation, mechanical tests (hardness, tensile, and Charpy), microstructural analysis, macro analysis, ferrite count measurement, scanning electron microscopy (SEM) analysis, and energy dispersive spectroscopy (EDS) analysis, as well as a general visual examination.
The results indicated unusual anomalous behavior of the HAZ and weld root areas. The puzzling results included acceptable tensile, hardness, and chemical tests at the parent and weld cap side but unacceptable test results at the weld root and the HAZ. The pitting corrosion was observed only at the root side within the defected girth welds.
The breakthrough of the failure investigation occurred when optical emission spectroscopy and positive material identification analysis showed the weld root of SS309 material and not of DSS UNS 31803. Additionally, the calculated PREN value also was of SS309 material at the weld root side. The microstructural analysis revealed the typical weld root morphology of SS309 with carbides and dendrites precipitating in the interdendritic regions. Close-up review of SEM examinations revealed the existence of cleavage facets within the damaged austenite islands in addition to slip-line formation and ductile tearing (Figure 2).
The type of welding involved during the whole process was gas tungsten arc welding (GTAW). Generally, GTAW welding gives very clean weld metal with good strength and toughness. Mechanization has substantially increased the efficiency of the process such that it has been used in applications such as cross-country pipelining. Gas shielding is also done during the GTAW process. Generally pure argon is used, although argon/helium mixtures have given some improvements by permitting faster travel speeds. Nitrogen, a strong austenite former, is an important alloying element, particularly in the super/hyper duplex steels. Around 1 to 2% nitrogen is sometimes added to the shield gas to compensate for any loss of nitrogen from the weld pool.2-4 Nitrogen additions will, however, increase the speed of erosion of the tungsten electrode. Purging the back face of a joint is essential when depositing a tungsten inert gas root pass. For at least the first couple of fill passes, pure argon is generally used although small amounts of nitrogen may be added, and pure nitrogen has occasionally been used.5 EDS analysis didn’t show any nitrogen content within the weld root side.
According to the authors, even though DSS is stronger, it does have some drawbacks with respect to welding. Conversely, it does have better corrosion resistance in chloride-containing environments than the austenitic range. Welding controls must ensure that the weld deposit matches the ferrite/austenite ratio of the parent material; excess austenite will make the alloy weaker and excess ferrite will make the alloy more susceptible to hydrogen cracking (subject to all other parameters kept constant).5-6 Despite these shortcomings, the strength of these steels and the superior corrosion resistance make them a natural choice for flowlines where the corrosion resistance is paramount. DSS materials can perform satisfactorily in sweet, sour, and chloride-containing environments within the limits suggested by different standards and other verified literature. Experience suggests that the problems most typical of DSS are associated with the HAZ, not with the weld metal. The HAZ problems are not hot cracking but rather a loss of corrosion resistance and toughness.
Conclusions
Overall, the probable root cause for the weld failure was the inappropriate filler wire (SS309) utilized for the root side welding facing a corrosive chloride-containing sour service environment. Additionally, there was also suspicion about incorrect back purge gas quality control during original construction, resulting in a locally diminished passivation layer at the root side. The use of the wrong filler material was an error at the site that was missed by the quality assurance/quality control personnel involved during the welding operation, as both SS309 and ER2209 looked similar in appearance at that time. Overall, this investigation and the tedious task of cutting and replacing the DSS pipes taught a good lesson to all the parties involved of having strong adherence to welding procedure specifications and procedure qualification records during welding operations. Moreover, the remaining flowlines with similar weld history were subjected to thorough inspection and weld repairs.
Acknowledgments
The authors would like to acknowledge the management of Penspen for their support in the preparation of this article. Many people were helpful in preparing this work, including Noel Denton, Ali Alani, Neale Carter, Nigel Curson, Brendan Kelly, and Mohammed Rizwin. Thanks to all of you.
References
1 M. Nauman, M. Rashid, “Case Study: Solving the Puzzle of 10-inch Duplex Stainless Steel Flowline Weld Failure,” CORROSION 2018, paper no. 11022 (Houston, TX: NACE International, 2018).
2 K.W Chan, S.C. Tjong, “Effect of Secondary Phase Precipitation on the Corrosion Behavior of Duplex Stainless Steels,” Materials (Basel) 7, 7 (2014): pp. 5,268-5,304.
3 J.R. Saithala, et al., “Corrosion Management of Duplex Stainless Steel Gas Flowlines,” Pipeline & Gas J. 241, 10 (2014).
4 G. Mathers, Duplex Stainless Steel Welding— Part 2 (Cambridge, U.K.: TWI).
5 J.P. Audouard, M. Verneau, “Evaluation of the Corrosion Resistance of High Nitrogen Containing Stainless Steels in Chloride and H2S/ CO2 Environments,” CORROSION/97, paper no. 36 (Houston, TX: NACE, 1997).
6 P.R. Rhodes, G.A. Welch, L. Abrego, “Stress Corrosion Cracking Susceptibility of Duplex Stainless Steels in Sour Gas Environments,” J. of Materials for Energy Systems 5 (1983): p. 3
This article is based on CORROSION 2018 paper no. 11022, presented in Phoenix, Arizona, USA.